Gaseous Fuels

301

8

Gaseous Fuels

8.1 INTRODUCTION

Solid and liquid fuels, along with their general thermochemical properties and combustion characteristics, were treated separately in Chapters 6 and 7. In this chapter, the remaining fuel category by phase, i.e., gaseous fuels, will be discussed. Depending on temperature and pressure, every pure compound can exist as a gas, liquid, and/or a vapor, and, obviously, gases can be liquefied. Many fuel gases, in fact, can be condensed simply by compression. Some, such as liquefied natural gas (LNG) and liquid hydrogen, require a supercold, or cryogenic, state in order to exist and will not remain in this condition without extreme refrigeration and insulation. For the sake of this discussion, therefore, a fuel will be considered to be a gas if it is noncondensable over normal temperatures and pressures. Examples of gaseous fuels include hydrogen gas, methane, and natural and synthetic natural gas (SNG). Vapors such as propane, butane, and liquefied petroleum gas (LPG) are fuels that are condensable over normal temperatures and pressures. Organizations such as the American Gas Association (AGA) are involved in supporting many aspects of fuel gas technology, including research and development within the natural gas industry, production of synthetic gas via coal gasification, and development of biomass-generated methane systems. Gaseous fuel science will continue to play an important role in combustion engineering in part because of the clean-burning nature of these energy resources, the fact that most fuels actually burn in the gas phase, and insights into the complex nature of general combustion processes that studies of simple gas-phase molecular reactions provide.

EXAMPLE 8.1 The specific gravity (SG) of gaseous fuels is expressed as the density, or specific weight, of the fuel at 15.56C and 1 atm to that of air at 15.56C and 1 atm. For these conditions, determine (a) the density of methane, CH4, kg/m3; (b) the density of propane, C3H8, kg/m3; (e) the specific gravity of methane; and (d) the specific gravity of propane.

2007 by Taylor & Francis Group, LLC

302 Chapter 8

Solution:

1. Density:

TP

RMWT

MWRRTP

=

== ,

CH4:

a. 343

kg/m10736.6(288.56K)K)m/kgmolekN 314,8(

)kN/m (101kg/kgmole)16( ==

C3H8:

b. 33 kg/m10852.1)56.288()314,8(

)101()44( ==

2. Specific gravity of gases:

air

gas

air

gas

atm 1C,56.15atm 1C,56.15

C56.15MWMW

SG ==

33air kg/m1022.1)56.288()314,8(

)101()96.28( ==

c. 552.097.28

1610220.110736.6

3

4

CH4 ===

SG

d. 519.197.28

4410220.110852.1

3

3

C 83 ===

HSG

Comments: Since the specific gravity of methane is less than 1, a methane leak will fill an entire enclosed space, while propane, with a specific gravity greater than 1, tends to settle to the bottom of the space. This effect produces fire hazards associated with methane leaks to be different from those for propane in an enclosed area. For methane, a spark anywhere could ignite an entire closed room, whereas for propane, the ignition would have to occur near the floor.

8.2 GASEOUS FUEL PROPERTIES

Recall from Chapters 1 and 7 that the specific gravity (SG) of gases and liquids is equal to the ratio of density for a particular fluid of interest to that of a reference compound. For liquids, the reference fluid is water; however, the reference for gases is air. Liquid density is only a function of temperature but, for gases, density is a function of both temperature and pressure and, therefore, the specific gravity of a gas is given as


Gaseous Fuels 303

F)(60C15.56 atm,1F)(60C15.56 atm,1

air

fuelgas

=

SG (8.1)

If ideal-gas behavior is assumed, the molar density of fuel gases is then equal to

= 33 ftlbmole

mkgmole

TRP (8.2)

and the specific gravity of these fuels is, therefore, equal to

air

gas

airgasgas MW

MWTP

RMW

TP

RMWSG =

= (8.3)

Equation (8.3) shows that a gaseous fuel having a specific gravity of less than 1.0 is lighter than air, whereas a fuel having a specific gravity greater than 1.0 is heavier than air. This property can be an important factor in the safety requirement for storing, handling, and even leakage considerations of a gaseous fuel; see Example 8.1. Table 8.1 lists specific gravities and critical constants for several gaseous fuels.

Constant-volume solid and liquid fuel bomb calorimetry, described in Chapter 6, is not used with gaseous fuels. Instead, gaseous fuel heating values are experimentally determined using the constant-pressure flow calorimeter shown in Figure 8.1. Gas and air are supplied at room temperature to the calorimeter unit. Energy released by burning gases is absorbed by cooling water flowing through a water jacket surrounding the burner. Regulated cooling water mass flow rate ensures that products of combustion exhaust from the calorimeter at room temperature. Precise measurement of the cooling water temperature rise and water mass flow rate allows experimental determination of the fuel energy release rate, i.e., kJ/sec (Btu/min). Gaseous fuel volumetric flow rates are obtained by use of a wet test meter. Flow calorimeters can experimentally measure heating values in a 3.7120 MJ/m3 (1003,200 Btu/ft3) range. An inability to maintain steady-state and steady-flow conditions, caused, for example, by fluctuations in water and/or gas source supply conditions as well as gas leaks within the calorimeter, can introduce significant experimental error and, hence, can predict erroneous heating values for a gaseous fuel.

The molar heat of combustion of methane, a major gaseous fuel constituent, is found in Table B.1 in Appendix B to equal

4CHHHV = (212,800 cal/gmole)(4.187) = 890,994 kJ/kgmole (8.4a)

or

= (212,800 cal/gmole)(1.8001) = 383,040 Btu/lbmole (8.4b)

The molar density of methane at STP can be obtained from Equation (8.2) and is equal to

32

CH kgmole/m0408.0K)(298K)m/kgmoleN314,8()N/m000,101(

4== (8.5a)


304 Chapter 8

Table 8.1 Gaseous Fuel Specific Gravities

Critical constants

T

SG P, atm C (F)

Paraffins Methane 0.554 45.8 81.9 116 Ethane 1.049 48.2 32.5 90 Propane 1.562 42.0 97.0 206 Butane (iso) 2.066 36.0 135.3 275 Butane (N) 2.066 37.5 152.6 306 Pentane (nee) 2.2-dimethyl propane 2.487 31.6 160.9 321 Pentane (iso) 2-methylbutane 2.487 32.9 188.1 370 Pentane (N) 2.487 33.3 197.0 386 Hexane (nee) 2.2-dimethylbutane 2.973 30.7 216.4 421 Hexane 2.3-dimethylbutane 2.973 30.9 227.6 441 Hexane (iso) 2-methylpentane 2.973 29.9 225.3 437 Hexane 3-methylpentane 2.973 30.8 231.4 448 Hexane (N) 2.973 29.9 234.8 454 Heptane 2.2.3-dimethylbutane 3.459 29.7 258.7 497 Heptane (iso) 2-methylhexane 3.459 27.2 258.1 496 Heptane (N) 3.459 27.0 267.6 513 Octane (iso) 2.2.4-trimethylpentanea 3.944 25.5 271.4 520 Octane 2.5-dimethylhexane 3.944 25.0 279.2 534 Octane (N) 3.944 24.6 296.4 565 Nonane (N) 4.428 22.5 322.0 611 Decane (N) 4.915 20.8 345.9 654 Naphtenes Cyclopropane 1.451 Cyclobutane 1.938 Cyclopentane 2.422 Cyclohexane 2.905 40.4 281.4 538 Olefins Ethylene-ethene 0.974 50.5 259.2 498 Propylene-propane 1.451 45.4 92.0 197 Butylene (iso) 2-methylpropane 1.934 39.5 145.3 293 Butylene (a) butene 1 1.934 39.7 147.0 296 Butylene (b) butene 2 2.004 40.8 155.3 311 Amylene (N) pentene 1 2.420 39.9 201.4 394 Diolefins Butadiene 1.3 1.869 42.7 152.6 306 Butadiene 1.2 1.869 Acetylene Acetylene-ethyne 0.911 61.6 36.4 97 Aromatics Benzene 2.692 48.6 289.8 553 Toluene-methylbenzene 3.176 40.1 321.4 610


Gaseous Fuels 305

Table 8.1 Continued

Critical constants

T

SG P, atm C (F) Miscellaneous gases Air 1.000 37.2 140.0 221 Ammonia 0.596 111.5 132.6 270 Carbon monoxide 0.967 35.0 138.6 218 Carbon dioxide 1.528 72.9 31.4 88 Chlorine 2.449 76.0 144.2 291 Hydrogen 0.0696 12.8 239.7 400 Hydrogen sulfide 1.190 88.8 100.9 213 Nitrogen 0.972 33.5 146.9 233 Oxygen 1.105 49.7 118.6 182 Sulfur dioxide 2.44 77.8 157.6 315 aRefers to isooctane, used as a standard in fuel testing. Organic chemists apply the same name to 2-methylheptane. Source: Cusick, C. F., Ed., Flow Meter Engineering Handbook, 3rd Edition, Minneapolis-Honeywell Regulator Company, Philadelphia, PA, 1961. With permission. or

3222

lbmole/ft00255.0R)R)(537lbf/lbmoleft454,1(

)ft/in144)(lbf/in7.14( == (8.5b)

By combining Equations (8.4) and (8.5), the volumetric heating value for methane is given as

HHVCH4 = (890,994 kJ/kgmole)(0.0408 kgmole/m3) = 36,350 kJ/m3 (8.6a) = (383,040 Btu/lbmole)(0.00255 lbmole/ft3) = 977 Btu/ft3 (8.6b)

The heating value of solid and liquid fuels is usually expressed in terms of a unit mass of fuel, whereas gaseous fuel heating values are most often specified on a per-unit volume basis. It is essential that energy reported for different fuels are compared on a consistent basis, i.e., per unit mole, unit volume, or unit mass. To illustrate, consider the molar heating values of methane and hydrogen:

)Btu/lbmole (383,040 kJ/kgmole994,8904CH =HHV (8.7a) and

)Btu/lbmole (122,977 kJ/kgmole043,2862H =HHV (8.7b) Equations (8.7a) and (8.7b) clearly show that, on a molar basis, methane has a greater heating value than hydrogen.


306 Chapter 8

Figure 8.1 Constant-pressure flow calorimeter. Adapted from Smith, M. L. and Stinson, K. W., Fuels and Combustion, McGraw Hill Co., New York, 1952.

The heating value for these two fuels on a volumetric basis is equal to

HHVHHV = (8.8) and

)Btu/ft977(kJ/m350,36)0408.0()994,890( 33CH4 ==HHV (8.8a) )Btu/ft314(kJ/m670,11)0408.0()043,286( 33H2 ==HHV (8.8b)

Equations (8.8a) and (8.8b) show that, on a unit volume basis, methane also has a greater heating value than hydrogen.

Finally, the heating value for these two fuels on a mass basis is equal to

MWHHVHHV = (8.9)

with

Btu/lbm)(23,940kJ/kg687,5516/994,8904CH ==HHV (8.9a)

and

Btu/lbm)(61,489kJ/kg022,1432/043,2862H ==HHV (8.9b)


Gaseous Fuels 307

Equations (8.8a) and (8.8b) indicate that, on a unit mass basis, however, hydrogen has a greater heating value than methane.

Propulsion heat engine fuel utilization usually involves vehicle weight and/or volume design restrictions. In these instances, the fuel-engine energy density require-ments of such machinery may dictate the use of fuels having high heats of combustion on both a unit mass and volume basis. This suggests that gaseous fuels in virgin form may not be best suited to mobility power requirements but, instead, are more compatible with heating and stationary power needs. Hydrogen has been successfully stored in hydride form for mobility use.

When combustion characteristics of gaseous fuels are matched with a particular gas burner, the fuel-engine energy interface requirements cannot be based on simply selecting fuels having an equal heating value or specific gravity alone. In fact, in order to pass a constant energy rate through a given burner orifice, gaseous fuels with equal operating gas pressure levels and pressure drop across the orifice must have an equal Wobble number, W0, where

SGW fuel gaseous of valueheatinghigher 0 = (8.10)

EXAMPLE 8.2 Hydrogen has been suggested to be a potential long-term replacement for natural gas. Considering methane to represent natural gas, calculate the heating value per unit volume, kJ/m, specific gravity, and Wobble number, kJ/m3, for (a) 100% CH4, (b) 75% CH425% H2, (e) 50% CH450% H2, (d) 25% CH475% H2, and (e) 100% H2 on a volumetric basis.

Solution:

1. Molar density for :TRP =

3

2

kgmole/m0.04077

K)(298K)m/kgmoleN314,8/(N/m000,101

==

2. Heating value for CH4-H2 mixture, using Table B.1 in Appendix B:

cal/gmole317,68cal/gmole800,212 24 HCH == HHVHHV and

3H

3

3CH

kJ/m660,11)4077.0()187.4()317,68(

kJ/m320,36

)kgmole/m(0.04077kJ/kgmole)187.4()800,212(

2

4

====

HHV

HHV

where

2444 HCHCHCHmixt )1( HHVxHHVxHHV +=


308 Chapter 8

a.

4CHx 2Hx 3kJ/mHHV

1.00 0 36,320 0.75 0.25 30,155 0.50 0.50 23,990 0.25 0.75 17,825 0 1.00 11,660

3. Specific gravity for CH4-H2 mixture:

]/[ airmixt MWMWSG = where

2444 HCHCHCHmixt )1( MWxMWxMW += b.

4CHx 2Hx MW SG

1.00 0 16.0 0.552 0.75 0.25 12.5 0.432 0.50 0.50 9.0 0.311 0.25 0.75 5.5 0.190 0 1.00 2.0 0.069

4. Wobble number for CH4-H2 mixture:

SGHHVW /0 = c.

4CHx 2Hx W0

1.00 0 48,890 0.75 0.25 45,880 0.50 0.50 43,020 0.25 0.75 40,890 0 1.00 44,390

Comments: A review of these results shows that the energy density per unit volume decreases as hydrogen is substituted for methane to almost one-third the original value; the specific gravity also drops as hydrogen substitution increases. However, the Wobble number remains fairly constant for the different CH4-H2 mole fractions.


Gaseous Fuels 309

Gaseous fuels have a greater role as a stationary power fuel because of environmental benefits associated with their clean burning benefits, but must be weighed against the energy costs placed on economic premiums of all fuel alternatives. The concentrations of CO, CO2, and O2 in the exhaust from natural gas and even oil-fired boilers and furnaces were historically measured by chemical absorption devices such as the classic Orsat analyzer shown in Figure 8.2. Many boiler applications can maintain efficient burner stoichiometry for operation by major exhaust, or flue gas composition measurements via an Orsat in conjunction with the boiler energy balance presented in Chapter 6.

Figure 8.2 Orsat flue gas analyzer. Adapted from Smith, M. L. and Stinson, K. W. Fuels and Combustion, McGraw Hill Co., New York, 1952.

A 100-ml flue gas sample can be drawn into an Orsat apparatus for analysis by lowering a displacing water bottle, which changes the hydrostatic head in the sampling loop. During fill, all the reagent bottle valves, as well as the atmospheric vent line valves, are closed. After the 100-ml volume is filled with exhaust, the sample line is closed, and the valve to the CO2 absorbent is then opened. The water-leveling bottle is raised until 100 ml of gas is passed into the CO2 absorbent, a 20% aqueous solution of potassium hydride. When the water-leveling bottle is returned to its original position, the reduction in the original 100-ml volume can be measured and is equal to the volume of CO2 in the original gas mixture sample. This process is repeated several times to ensure complete CO2 removal. Next, oxygen is removed by passing the gas sample back and forth several times between the 100-ml sample volume and the second reagent bottle, which contains an aqueous alkaline solution of pyrogallic acid. The percentage of oxygen by volume in the original gas sample is determined by noting an additional reduction of the remaining gas contained in the 100-ml sample volume. The last reagent pipette contains an aqueous solution of cuprous chloride, which absorbs CO and allows the volume percentage of CO in the sample to be determined as well. This order of absorption is critical to ensure


310 Chapter 8

reliable results. The Orsat analysis yields a dry product analysis, as shown in Example 8.3, and assumes that the remaining gas is N2. More complex and sensitive methods of detection, such as ultraviolet and infrared emissions spectroscopy, ultraviolet absorption spectroscopy, and mass spectrometry, which are used to determine the presence of minute amounts of unburned hydrocarbons and nitric oxides, are used.

EXAMPLE 8.3 An exhaust gas sample consists of the following numbers of moles of gaseous species:

Moles CO2 = N1 Moles CO = N2 Moles H2O = N3 Moles O2 = N4 Moles N2 = N5

The sample is analyzed using an Orsat analyzer. Show that the actual volumetric analysis for CO2 (using an Orsat apparatus) equals the sample volume of CO2, based on a dry analysis of the products.

Solution:

1. Initial total gas sample volume:

TRNVP tottottot = where

TRNNNNNVPNNNNNN

VT

P

)(

units100analysis duringconstant

analysis theduringconstant atm1

54321tottot

54321tot

tot

tot

++++=++++=

==

==

2. Since liquid and water vapor are in direct contact during the entire analysis, the partial pressure of the water vapor remains constant in the apparatus, or

constsatOH2 == TPP thus,

5432

3

54321

3

tot

OHOH

2

2 NNNNN

NNNNNN

PP

x +++=++++==

NOTE: Ntot is changing because of the absorption of CO2 and, thus, the moles of water vapor, ,OH2N also have to change.


Gaseous Fuels 311

3. Total gas sample after removal of CO2:

TRNNNNVP )( 54321tot +++= where

3223 analysisCOafter OH of moles NN =

4. Volume percent associated with CO2 removal:

100CO%tot

1tot2

=

VVV

tot

54321tot

][P

TRNNNNNV ++++=

and

tot

54321

][P

TRNNNNV +++=

where

)()()(

54321

543254321

tot

1tot

NNNNNNNNNNNNNN

VVV

+++++++++++=

)basisdry CO

5421

1

54321

5421543211

54321

3542154231

54321

331

tot

1tot

2

)()/()(

)()]/()[(

)(

xNNNN

N

NNNNNNNNNNNNNNN

NNNNNNNNNNNNNNN

NNNNNNNN

VVV

=+++=

+++++++++++=

++++++++++=

+++++=


Table 8.2 Gaseoues Fuel Characteristics

Heating Value SG kJ/m3 Btu/ft3

Type

CO2 O2 N2 CO H2 CH4 C2H6 C3H8 C4H10

Illumi- nants and

Others

Gross Net Gross Net

Natural Natural Natural Natural Natural Propane Propane Butane Butane Refinery oil Refinery oil Oil gas Coal gas Coal gas Coal gas Coke oven Producer Producer Blast furnace Blue gas (water gas) Blue gas (water gas) Carbureted water Carbureted water Carbureted water Sewage

. . . .

. . . . 6.5 0.8

. . . .

. . . .

. . . .

. . . .

. . . .

. . . . 0.2 1.2 2.4 1.7 2.1 2.2 8.0 4.5 11.5 5.4 5.5 3.6 6.0 0.7 22.0

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . . 0.2 0.2 0.5 0.8 0.8 0.4 0.8 0.1 0.6

. . . . 0.7 0.9 0.4 0.9 0.3

. . . .

5.0 0.8

. . . . 8.4

. . . .

. . . .

. . . .

. . . .

. . . . 0.6 0.5 2.4 11.3 8.1 4.4 8.1 50.0 50.9 60.0 8.3 27.6 5.0 12.4 5.8 6.0

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . . 1.2 1.2 7.7 7.4 7.3 13.5 6.3 23.2 27.0 27.5 37.0 28.2 21.9 26.8 11.7

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . . 6.1 13.1 54.2 48.0 49.5 51.9 46.5 17.7 14.0 1.0 47.3 32.5 49.6 32.2 28.0 2.0

90.0 83.4 77.5 84.1 36.7

. . . .

. . . .

. . . .

. . . . 4.4 23.3 30.1 27.1 29.2 24.3 32.1 1.0 3.0

. . . . 1.3 4.6 10.6 13.5 36.1 68.0

5.0 15.8 16.0 6.7 14.5 2.2 2.0

. . . .

. . . . 72.5 21.9

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . . 2.5

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . . 23.5

97.3 72.9 6.0 5.0

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . . 14.9 0.5 0.8 94.0 66.7

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . . 10.4*

. . . . 24.3#

. . . . 28.3 . . . . 39.6 3.9 3.0 3.4 3.4 4.0

. . . .

. . . .

. . . .

. . . . 0.7 6.1 8.2 17.4

. . . .

0.60 0.61 0.70 0.63 1.29 1.55 1.77 2.04 2.00 1.00 0.89 0.37 0.47 0.47 0.42 0.44 0.86 0.86 1.02 0.57 0.70 0.54 0.66 0.63 0.79

37,300 42,060 39,970 36,280 79,460 95,290 93,280 119,580 118,610 61,470 54,950 21,230 20,190 22,310 19,370 21,200 5,330 6,070 3,430 10,690 9,690 19,970 19,740 31,290 25,700

33,680 38,030 36,170 32,740 72,980 87,840 86,280 110,300 109,300 56,770 50,330 19,000 18,100 20,120 17,360 18,960 4,950 5,700 3,430 9,760 8,900 17,170 16,800 28,680 23,130

1,002 1,129 1,073 974 2,133 2,558 2,504 3,210 3,184 1,650 1,475 570 542 599 520 569 143 163 92 287 260 536 530 840 690

904 1,021 971 879 1,959 2,358 2,316 2,961 2,935 1,524 1,351 510 486 540 466 509 133 153 92 262 239 461 451 770 621

Source: American Gas Association, 1948. Used by permission of the copyright holder. *C5H12 #C3H6 C4H8 At 60 and 30 in. Hg.

312 Chapter 8


Gaseous Fuels 313

8.3 NATURAL GAS

The worlds most readily available and abundant gaseous fuel resources are found in natural gas reserves. Gaseous fuels have been used for centuries in China and for over 100 years in both the United States and Europe. In the United States, when natural gas was originally discovered at oil wells, it was burned, or flared off, as a useless by-product of oil production. Today, natural gas is a major industry that transports fuel throughout the United States by a complex interstate pipeline network. Natural gas was formed by anaerobic, or bacterial-assisted, decomposition of organic matter under heat and pressure and, therefore, like coal and crude oil, is a variable-composition hydrocarbon fuel. Table 8.2 lists properties of certain natural and synthetic gas resources. Synthetic natural gas (SNG) production and anaerobic digester technology will be discussed in Sections 8.4 and 8.5.

Natural gas consists chiefly of methane, ranging anywhere from 75% to 99% by volume, with varying concentrations of low molecular weight hydrocarbons, CO, CO2, He, N2, and/or H2O. Conventional gas well drilling has proved successful in or near oil fields. New and additional unconventional drilling methods are finding reserves in deep wells and coal beds, as well as in shale and tar sands. Natural gas is practically colorless and odorless and, for safety reasons, is soured with the familiar rotten egg odor by adding hydrogen sulfide, H2S. The American Gas Association classifies natural gas as sweet or sour gas and, additionally, as being associated or nonassociated gas. Associated, or wet, gas is either dissolved in crude oil reserves or confined in pressurized gas caps located on the top of oil ponds. Wet gas has appreciable concentrations of ethene, butene, propane, propylene, and butylenes. Nonassociated, or dry, gas can be found in gas pockets trapped under high pressure that have migrated from oil ponds or are the results of an early coalization gasification stage. Natural gas, like coal and oil, has regional characteristics. For example, western U.S. natural gas fields generally contain substantial amounts of CO2, Midwestern reserves have higher N2 concentrations and some He, and eastern gas is high in paraffins. European gas reserves are basically high in CO2, H2, and olefinic hydrocarbons.

Liquid petroleum gas, or LPG, consists of condensable hydrocarbon vapors recovered by expansion of wet gas reserves. By compressing the condensable fractions, liquefied fuel vapors, such as commercial propane and butane, can be stored and transported at ambient temperatures as a liquid. Liquefied natural gas, LNG, is the condensed state of dry natural gas but requires a cryogenic refrigeration for storage and handling at 102C (260F). Efficient transportation of large Middle Eastern natural gas to the United States, Europe, and Asia by sea would require use of specially designed LNG tankers.

EXAMPLE 8.4 A natural gas has a volumetric analysis of 95% CH4, 3% C2H6, and 2% CO2. For conditions of 14.7 psia and 77F, calculate (a) the higher heating value of the fuel, Btu/ft3 of gas; and (b) the lower heating value of the fuel, Btu/ft3 of gas.


314 Chapter 8

Solution:

1. Stoichiometric equation:

222

222624

NOHCO]N76.3O[]CO02.0HC03.0CH95.0[

dcba

++++++

Carbon atom balance:

0.02 + 0.95 + 0.06 = b = 1. 03

Hydrogen atom balance:

(4)(0.95) + (6)(0.03) = 2c c = 1.99

Oxygen atom balance:

(2)(0.02) + 2a = (2)(1.03) + 1.99 a = 2.005

Nitrogen atom balance:

d = 3.76a = (3.76)(2.005) = 7.539

2. Energy balance:

jfjjifiihhNhhNQ ][][ 0

react

0

prod +=+=

==

or

22

262

42

22

N0

O0

CO0

HC0

CH0

N0

OH0

CO0

])[76.3()005.2(][005.2

][02.0][03.0

][95.0])[005.2()76.3(

][99.1][03.1

hhhh

hhhh

hhhh

hhhhQ

ff

ff

ff

ff l

++++

++++++=

Recall that the higher heating value assumes water in the products is a liquid.

From Table B.1 in Appendix B,

Btu/lbmole033,384

)cal/gmole

Btu/lbmole(1.8001cal/gmole)(213,340

cal/gmole340,213

344,213)054,94(02.0)236,20(03.0)889,17(95.0)317,68(99.1)054,94()03.1(

===

=+=

HHV

Q


Gaseous Fuels 315

3. Density, fuel:

3

222

lbmole/ft00255.0

R)R)(537lbf/lbmoleft545,1()ft/in.144)(lbf/in7.14(

=== TR

P

4. Higher heating value, water as liquid in product:

)lbmole/ft(0.00255)Btu/lbmole033,384( 3=HHV a. 3Btu/ft980=HHV

5. Lower heating value, water as vapor in product:

Btu/lbmole279,346b.OH lbmole

lbm18OH lbm

Btu054,1fuel lbmole

OHlbmole99.1

fuel Btu/lbmole033,384

6899.1

22

2

=

+=

=

LHV

LHV

FhHHVLHV fg

8.4 COAL-DERIVED GASEOUS FUELS

Synthetic, or manufactured, gaseous fuels have been generated using coal resources for more than 100 years. Coke and coke gas, by-products of coal used in the iron industry, were produced as early as the eighteenth century. Towngas, a commercial and residential grade low-Btu fuel, was used during the late nineteenth and early twentieth centuries until replaced by electric power as well as by the oil and natural gas industries. Most coal-derived fuel gas technologies fall into one of three general categories: coal pyrolysis, coal gasification, or coal catalytic synthesis. Today, many factors point toward a need for redeveloping a coal-derived syngas industry. These factors include:

Large U. S. coal reserves ill suited for direct combustion Environmental pressure for greater coal combustion pollution abatement Sulfur removal as H2S during gasification versus sulfur generation as SO2 during

combustion Market for clean-burning, coal-based fuel gas in stationary power plants Transportable Synthetic gaseous fuel via pipelines


316 Chapter 8

Coal is a poor feedstock, however, for making a commercially viable gaseous fuel, in part because of the following properties:

Natural occurrence as a solid Variable and nonuniform nature Poor conversion energetics and economics Lower overall gasification energy efficiencies as compared to direct combustion

efficiencies

Carbonization, or pyrolysis, is a destructive thermal distillation process in which volatile combustible fractions contained in raw coal or coke (such as hydrogen, methane, ethyene, and carbon monoxide) are driven off. Yields are relatively low with 70 wt % of the original coal remaining as a solid residue after devolatilization. To release gases, coal or coke is placed in a closed vessel, or retort, and heated by external coal combustion to a temperature range of 5301,000C (9851,830F). Coal and coke gas have properties that are a function of the particular coal supply, actual pyrolysis temperature, specific type of retort being used, and total residence time of reactants within the vessel. These gas energy volumes cover the range 18,63024,220 kJ/m3 (500650 Btu/ft3).

An alternate means of producing syngas is by partial combustion and thermal cracking of an incandescent solid fuel bed of coal, coke, peat, or even wood with air. Producer gas, for example, is generated by fuel-lean combustion, which occurs in a reacting bed of coal or coke. The initial stages of gasification result from partial combustion of the bottom coal to yield carbon dioxide and heat (see Figure 8.3). Thermodynamically, this process can be represented by the reaction

CS + O2 CO2 + heat (8.11) Exothermic reactions within the remaining coal bed with carbon dioxide and heat then produce carbon monoxide or

Heat + CS + CO2 2CO (8.12) Overall, then, the gasification of coal can be expressed as

2CS + O2 2CO (8.13) Producer gas has a low energy volume of 5,2206,700 kJ/m3 (140180 Btu/ ft3) because of a high percentage of nitrogen present in the gas, approximately 50 vol %.

The low yields of gas resulting from coal pyrolysis and the relatively low energy content of producer gas, approximately 1020% that of natural gas, limit their use to special applications at local production sites. One means of upgrading producer gas, for example, would be to reduce the mole fraction of nitrogen in product gas by using oxygen instead of air. Steam-cracking coal at elevated temperature and pressure generates carbureted water gas, a synthesis gas that also has a lower nitrogen content and, therefore, greater energy volume than producer gas. Carbureted water gas production is initiated by blowing pyrolysis air through coal for 12 min, followed in turn by a 24 min blast of steam through the incandescent bed to hydrogasify the coal. This entire process is repeated continuously to produce a steady stream of gas having an energy volume of approximately 10,060 kJ/m3 (270 Btu/ft3) (see Figure 8.4). Steam cracking or reforming of coal can be represented thermodynamically by the equilibrium reaction

CS + H2O PT ,

CO + H2 (8.14)


Gaseous Fuels 317

Figure 8.3 Producer gas generator. Adapted from Smith, M. L. and Stinson, K. W., Fuels and Combustion, McGraw Hill Co., New York, 1952.

Figure 8.4 Carbureted water gas generator. Adapted from Smith, M. L. and Stinson, K. W., Fuels and Combustion, McGraw Hill Co., New York, 1952.


318 Chapter 8

Oil gas or fuel oil can be sprayed into carbureted water gas during processing to further raise the heating value to 18,63022,350 kJ/m3 (500600 Btu/ft3). Carbureted water gas is often referred to as blue gas since carbon monoxide in this gaseous fuel burns with a characteristic short blue flame.

Russian engineering in the 1930s pioneered underground hydrogasification of coal by injecting steam directly into coal beds. By 1938, this technique was supplying coal gas on a commercial basis within the Soviet Union. This technology has been considered by the U.S. coal industry as a potential method for utilizing the vast reserves of relatively low-grade, environmentally unburnable western coal. However, because of the large amount of water required, the limited availability of usable water resources in the region, and the worlds growing critical water crisis, this is a questionable technology for gasifying U.S. coal.

Producer gas, a low-Btu coal gas made with nineteenth-century coal conversion technology, cannot be economically transported and, therefore, is not a viable substitute for natural gas. A full-scale commercial industry that could supply a coal-derived synthetic natural gas, SNG, would require large water and energy inputs, along with development of more complex and yet unproven commercialized technologies. Environ-mental concerns over burning high-sulfur coal may spur development of this alternate coal utilization even though SNG will be more expensive and less efficient than direct combustion of coal. In addition, future depletion of both proven and projected natural gas reserves would impact existing gas supplies and pipeline distribution.

EXAMPLE 8.5 One mole of CO and 220% theoretical oxygen, both at 25C, undergo a steady flow reaction at 1-atm pressure. Neglecting dissociation of O2, determine (a) the final equilibrium composition, and (b) the final temperature if the process is adiabatic.

Solution:

1. Stoichiometric reaction:

CO + O2 CO2 2. Actual reaction:

CO + (2.2)(0.5)O2 aO2 + bCO + cCO2 Carbon atom balance:

1 = b + c

Oxygen atom balance:

3.2 = 2a + b + 2c 3.2 = 2a b + 2 1.2 = 2a b

3. Energy balance for P = C (adiabatic):

jjii

jjii

eNeN

eNeNWQEd

=+=


Gaseous Fuels 319

22

2

CO0

CO0

O0

O0

CO0

][][][

][1.1][

hhchhbhha

hhhh

fff

ff

+++++=+++

4. Equilibrium constant:

) ) )COO2

1CO

2221

loglogloglogCOOCO

22ppPp KKKK =

+

and

21

21

2

2

21

2

20

COO

CO

CO0O0

CO0

]/[]/[

]/[

== P

PP

P

PPPP

PPK P

Now,

tot0 Patm1 =P and

cbaax

PxP ii

++==

2O

tot

cbacx

cbabx

++=++=

2CO

CO

or

)()()()(

21

21

bacbacK p

++=

5. From item 2, then, one can eliminate b and c, obtaining

ac

abaa

22.22.12

==

=

and

)2.12()1()22.2(

21

21

+=

aaaaK p


320 Chapter 8

6. Since the final state is unknown, i.e., T2, a, b, and c, an iterative technique is required for solution.

7. Initial guess for T2 = 2,800K: Energy balance using data found in Table B.1 in Appendix B:

26,416 = a(+21,545) + (2a 1.2)(26,416 + 20,582) + (2.2 2a)( 94,051 + 33,567)

or

a = 0.762

Equilibrium constant:

173.3]2.1)762.0()2[(]762.0[

]762.1[)]762.0()2()2.2[(2

1

21

==pK

From Tables B.4 and B.5 in Appendix B,

683.6

825.0563.6388.7log

===

p

p

K

K

8. Second estimation for T2 = 3,000K:

)535,36051,94()22.2()357,22416,26()2.12()446,23(416,26

++++=

aaa

a = 0.731


055.3

485.0407.6892.6log

335.4]2.1)731.0()2[(]731.0[

]731.1[)]731.0()2(2.2[2

1

21

==

==

P

p

p

K

K

K

9. Third estimation for T3 = 2,900K:

)049,35051,94()22.2()469,21416,26()2.12()493,22(416,26

++++=

aaa

a = 0.746


709.3]2.1)746.0()2[(]746.0[

]746.1[)]746.0()2(2.2[2

1

21

==pK

log Kp = 7.132 6.483 = 0.649 Kp = 4.46


Gaseous Fuels 321

10. From the graph, T2 ~ 2,970K:

a ~ 0.740 b ~ 0.280 c ~ 0.720

or

CO + 2.2 O2 0.740 O2 + 0.280 CO + 0.72 CO2

There are no known direct coal-methanization conversion processes. The overall equilibrium reaction

CS + 2H2Og CH4 + CO2 (8.15) suggests favorable thermodynamics in that the heat of reaction is approximately zero, but no catalyst has been found that will allow this overall process to occur. Bioconversion of cellulose and other organic materials, covered in the next section, can generate methane directly.

Current and conversion technologies require pretreatment gasification and methanization in order to produce a pipeline-quality SNG (Figure 8.5). Development and application of various designs will differ in their coal selection as well as the means they use to introduce coal and either air or oxygen into the gasifier. Pretreatment of coals that cake requires mild oxidation to prevent caking during gasification. Gasification begins with heating and drying of the coal. Devolatilization or distillation will drive off evolved gases, with the initial heating raising the coal to near its softening temperature. Chemical conversion reacts coal with oxygen, or air, and steam. Recall that this chemical conversion will yield a low-Btu product if air is used, while a low-nitrogen or medium-Btu gas will be produced with the use of oxygen or water. The degree of chemical conversion is related to equilibrium shifts in the products CO, CH4, and H2 or

2C + O2 2CO2 (8.16) C + H2O CO + H2 (8.17) C + CO2 2CO (8.18)


322 Chapter 8

Figure 8.5 Coal gasification schematic. Adapted from Department of the Navy Energy Fact Book, Report No. TT-A-6054-79-403, 1979.

Several coal gasifiers are being commercially developed and include fixed or moving beds, entrained flow, fluidized beds, and molten bed systems. The Lurgi fixed-bed gasification technique feeds coal at the top of a gasifier, with steam or air supplied at the bottom, allowing gasification to occur as the coal passes down through the gasifier; see Figure 8.6. The Kopper, an entrained flow system, feeds a mixture of pulverized coal and air/steam or oxygen/steam to the gasifier. Gasifiers can be further categorized as either slagging or dry, depending on whether they are operated above or below ash fusion temperature. Coal gasification chemically reduces sulfur to hydrogen sulfide, H2S, during the pyrolysis stage. Extraction of H2S yields a sulfur-free synthesis gas.

Catalytic methanization of synthesis gas is required to produce an SNG of approximately 9598% methane and occurs via the reaction

CO + 3H2 CH4 + H2O (8.19) The major thrust of current coal gasification programs is to optimize methane

production by conducting hydrogasification at much higher pressures and temperatures than those used in traditional coal gas production. Future technological breakthroughs are hampered by the very complex, non-uniform, and variable composition of U.S. coal resources. Development of coal-based SNG having pipeline quality will be strongly influenced by the going price of energy alternatives and the ready availability of alternate gas resources.

Ash


Gaseous Fuels 323

Figure 8.6 Lurgi coal gasification. Source: Hammond, A. L., Metz, W. D., and Maugh II, T. H., Energy and the Future, American Association for the Advancement of Science, Washington, DC, 1973, 120. With permission of author.


324 Chapter 8

8.5 BIOMASS AND SYNTHETIC NATURAL GAS

Resources other than coal or crude oil can be used as feedstock for generating a synthetic gaseous fuel. This synthetic natural gas, or biogas, can be produced from a variety of organic materials, including vegetation, animal and plant residue, and municipal solid wastes (MSW). A renewable methane fuel resource can be derived from solar energy stored in naturally occurring organic materials, as well as from certain wasteful by-products of modern industrialized civilizations by microbiological conversion processes, direct material pyrolysis, or thermochemical technologies.

Microbiological conversion, based on the metabolic process of certain bacteria, can consume cellulose found in vegetation or manures produced by livestock and yield methane, carbon dioxide, and undecomposable or digested sludge as their by-products. Marsh gas is a natural methane produced from decayed organic matter submerged in stagnant water and is itself the source of the ghostly will-o-the wisp observed in swampy areas. Bacteria required for natural or commercial microbiological methane conversion processes need oxygen to reproduce. Anaerobic bacteria are those that thrive on chemically combined oxygen, while aerobic bacteria can exist only on dissolved oxygen and are therefore referred to as being oxygen-free (Figure 8.7).

Moist biomass feedstock is first converted by acid-forming, or aerobic, bacteria to simple organic compounds, chiefly organic acids and carbon dioxide. These intermediate products are then fermented by anaerobic bacteria, yielding methane and additional carbon dioxide as by-products. This anaerobic digester gas product is approximately 5067% methane, 5033% CO2 by volume with approximately 1040 ppm hydrogen sulfide.

Specially designed digestion tanks, or digesters, are used commercially to accomplish this anaerobic biomass conversion process. In order to sustain a conversion process within an artificial digester environment, bacteria health and growth require precise monitoring and control of the following:

Proper balance between acid-forming and methane-forming bacteria Proper solids-to-liquid ratio (79% solids):

spercentagestock raw

solids) %4030(solids)%18(

solids)%5(

wastesvegetablemanureanimal

sewage

Proper pH between 7.5 and 8.5 or near neutral (7) Proper phosphorus, nitrogen, and other nutrients levels Proper digester temperature of 2060C (68140F) The anaerobic mesophilic bacteria, which can exist between 20 and 40C (68 and 104F), require 20 days to digest, while the aerobic thermophilic bacteria can exist in a 4960C (120140F) environment and require only 78 days for conversion.

Methane digester history can be traced back to ancient China, where methane was produced in sewage lagoons, and to nineteenth-century England, where sewer gas was used to supply lamp gas for street illumination in London. Small-scale digester technology applications can be found throughout the world today, including areas of India, France, Germany, and the United States.


Gaseous Fuels 325

Figure 8.7 Aerobic and anaerobic biogas production.

Large land acreage suitable for farming would be required to grow sufficient photosynthetic fuel crops necessary to sustain a viable biomass industrial gas industry. Such an industry, which must also need water for the biomass conversion process, would therefore compete directly with the current utilization of fertile land and water resources for producing food. Regions of humid tropics and temperate zones where large parcels of uncultivated lands and low per capita energy consumption exist hold greater promise for biomass fuel production and use.

Aerobic destruction, or composting, converts organic wastes into a stable humuslike product, the chief value of which is its use as a soil conditioner and fertilizer. Composting will not generate a gaseous fuel but can stabilize and neutralize organic wastes prior to their disposal. Suitable geological conditions at landfill sites where untreated organic and municipal wastes have been buried, however, can promote anaerobic methane generation. Methane in old sanitary landfills is often vented and/or flared off to minimize the explosive risks of gas pockets building up within disposal sites. At selected dump sites, unnatural or landfill gas can be drilled, piped, and treated to remove carbon dioxide, moisture, hydrogen sulfide, and other contaminants and can yield a pipeline-quality gas.

Several biomass gasification techniques for producing a commercial fuel gas are in various stages of research and development today. Biomass gasification is difficult as a result of, among many factors, the nonhomogeneous and fibrous complexity of these organic materials. As such, proposed conversion technologies differ in their design approach to selecting operating pressure, temperature, biomass preparation, and time needed for the conversion reaction. Endothermic destructive distillation, or pyrolysis, of


326 Chapter 8

organic materials at 430450C (805841F) can yield a gas having an energy density near that of a coal-derived medium-Btu gas. Municipal solid waste, for example, can be used to produce a low [3.735.59 MJ/m3 (100150 Btu/ft3)] to medium [11.214.9 MJ/m3(300400 Btu/ft3)] gas by pyrolysis. Thermal decomposition of these organic wastes in substoichiometric or oxygen-deficient atmospheres will shift from gas product mixtures rich in methane-carbon dioxide to mixtures rich in hydrogen-carbon monoxide as pyrolysis temperature increases. In addition to pyrogas, small amounts of oil, charred metals, solid materials containing glassy aggregate, carbon char, and considerable bottom and fly ash will result from municipal waste pyrolysis. Gasification techniques differ in degree of carbon gasification and amount of air utilized per unit of organic mass converted. Catalytic hydrogenation uses a hydrogen-rich environment, which is heated to temperatures in excess of 300C (908F) for biomass gasification. Newer gasification systems utilizing fixed-bed and/or fluidized-bed reactors, similar to the solid fuel combustion systems described earlier in this text, are currently being evaluated and pursued.

Waste in a landfill, once covered to restrict the inward diffusion of oxygen, can generate methane in the presence of moisture and heat by anaerobic bacteria activity. Biodegradation yields a raw gas containing nominally 4560% CH4 with 3550% CO2 by volume. The remaining constituents consist of N2, O2, trace hydrocarbons, and hydrogen sulfide.

Landfill gas recovery operations are similar to those at a natural gas field except that collection up to the compressor is under vacuum. Wells drilled into the landfill site to extract gas remove a substantial amount of water along with the gas under the vacuum abstraction process. This water, along with nonmethane hydrocarbon compounds, must be removed after the collection and compression process. Benefits for recovering landfill gas include:

Provides a gaseous fuel resource which, after treatment, is comparable to natural gas

Reduces buildup of trapped gas generated in landfills from dangerous levels with the potential for explosion

Produces a cleaner burning gas fuel than natural gas

To provide a high-Btu (i.e., pipeline quality) gas, any CO2 and hydrogen sulfide must be removed. Successful landfill gas recovery is dependent on the location and age of each particular site. Profitable recovery is highly reliant on favorable economics driven by the recovery process characteristics, desired end product quality, and particular nature of the end use of the fuel product.

In the previous sections, several alternative and potential substitutes for natural gas were considered. The viability and development of any and all of these synthetic gaseous fuel alternatives will depend on numerous factors including:

Successful economics of scale in their development and commercialization Ability to compete successfully against other alternatives Environmental impact of their fuel production process and combustion charac-

teristics


Gaseous Fuels 327

8.6 HYDROGEN

Alternatives are apparently available to substitute for any major worldwide natural gas shortage in the near-term future. The long-term gaseous alternative fuel resource of the future is considered by many to be hydrogen. Environmentally, diatomic hydrogen is the cleanest-burning fuel since its combustion produces only water and oxides of nitrogen.

H2 + a[O2 + 3.76N2] bH2 + cH2O + dO2 + eN2 + f NOx. (8.20) Hydrogen, therefore, holds promise as a long-term fuel option because, when burned in air, it also generates no unburned hydrocarbons or carbon dioxide, a compound that contributes significantly to the greenhouse effect of the Earth's upper atmosphere.

Certain properties of diatomic hydrogen gas give it its unique fuel characteristics. The specific gravity of gaseous hydrogen, for example, is approximately 0.07, meaning that it is less dense than methane, is lighter than air, and requires a greater normal storage volume than natural gas. Hydrogen burns differently than natural gas, partly because of its lower ignition energy, higher laminar flame speed, invisible but hotter flame, and broader explosive fuel-air mixture limits. Furthermore, the heat of combustion for gaseous hydrogen on a volumetric basis of 12.0 MJ/m3 (320 Btu/ft3) is approximately one-third that for natural gas, whereas the heat of combustion on a mass basis is 2.75 times that of most hydrocarbon fuels. Hydrogens high diffusivity also means that it has a greater leak rate than natural gas, is able to embrittle metals, and can be absorbed by certain solid materials termed hydrides. The saturation state for hydrogen at 1 atm of 253C (424F) requires that liquid storage must be at cryogenic conditions, a state that cannot be achieved by simply compressing and cooling hydrogen gas.

Producing heat by hydrogen combustion with air or oxygen can result in both high temperatures and high NOx emissions. On the other hand, the nature of the hydrogen flame allows hydrogen to be burned at conditions even as low as 500C (932F) in a low temperature flameless catalytic burner. Low NOx emissions can thereby be achieved in heating applications in the 8001,500C (1,4722,732F) temperature range by use of the low-temperature flameless catalytic combustion of hydrogen.

Currently hydrogen generation is predominantly for use in crude oil refining, ammonia production, as well as other industrial operations. An infrastructure to potentially supply enough hydrogen capacity for a national transportation network, however, is presently unavailable and currently unachievable.

Unfortunately, hydrogen gas does not occur naturally and, hence, must be generated, which requires both a source material and an energy input. Hydrogen, however, is an abundant element contained in many different substances including gases like methane and ammonia, liquids such as crude oil and water, and solids like coal and shale. In the short term, hydrogen can be produced by steam-reforming natural gas via the water-gas reaction or

CH4 + 2H2O PT ,

CO2 + 4H2 (8.21)

and by steam-reforming coal via the carbureted water-gas reaction

CS + H2O PT ,

CO + H2 (8.22)


328 Chapter 8

Steam reforming, the most prevalent commercial means of producing hydrogen, utilizes a hydrogen-rich donor such as natural gas. Refineries make use of on-site hydrocarbon feedstocks, i.e., natural gas (methane) or other light hydrocarbons (such as LPG or naphtha) to generate hydrogen by steam reforming for use in the crude oil refining process. Steam reforming as well as gasification of nonhydrocarbon sources such as coal can also produce hydrogen by use of the technologies described previously in Section 8.4. Gasification and pyrolysis of biomass sources have also been considered as a potential source for producing hydrogen. Processing coal to produce hydrogen raises by-product and pollution issues and current projected production methods are not even cost competitive with steam reforming methane. Note also that many of these resources are also considered suitable feedstock for producing alternate liquid and gaseous synfuels.

In the long term, hydrogen can be generated by the electrolysis of water.

2H2O PT ,

H2 + O2 (8.23)

Any use of electrical energy to make hydrogen via water electrolysis competes with the direct utility use of electricity. Hydrogen production and electric power generation could be combined during off-peak hours of electrical power demand, though, as a means of load leveling and energy storage at utility power plants. An unusual concept, shown in Figure 8.8, uses heat generated from fissionable radioactive waste to produce steam which, in turn, generates electricity required for water electrolysis. Eventually, a solar electrical energy/hydrogen economy would be independent of any petrochemical, coal, or even nuclear energy systems.

Several positive reasons for developing a viable hydrogen fuel industry can be identified, including the obvious fact that it is the long-term renewable fuel of the future. Hydrogen is a clean-burning fuel that could become a viable long range alternative to depleted crude oil based hydrocarbon reserves and if the processing of coal-derived fuels are environmentally restrictive. Hydrogen is also an essential ingredient required to upgrade many of the liquid syncrudes mentioned in Chapter 7. However, when discussing the environmental benefits of hydrogen as a fuel, one must also address the pollution issues associated with any hydrogen generating process.

Hydrogen, like electricity, is an energy carrier that could be transported from production to particular sites by pipelines for specific uses. Some have therefore suggested hydrogen as a possible replacement for natural gas, but there appears to be sufficient new natural gas resources, as well as additional syngas resources, that would be able to meet current natural gas needs. Finally, a hydrogen fuel industry would have to be established and the world's entire energy infrastructure drastically changed in order to effectively transition to hydrogen utilization as a major new fuel resource.

Spark-ignition engines have been demonstrated that can use hydrogen as a fuel but, with on-board vehicle fuel storage restrictions, relatively high cost of the fuel, lack of any available fuel distribution, and poor public acceptance, this capability of hydrogen has made limited commercial advancement. Transportation uses of hydrogen fueled engines are severely limited by their need for compact H2 storage, either as a cryogenic liquid, in anhydrides like iron titanium hydride FeTiH2, in pressurized gaseous state, or in hydrogen-containing fuel-reforming compounds like methanol. Today there is an increas-ing environmental motivation for development and use of hydrogen-fueled vehicles in certain high-pollution density metropolitan areas.


Gaseous Fuels 329

Figure 8.8 The hydrogen economy: (a) production, from Nelson, M. E., Keating, E. L., Govan, D. R., Banchak, R. J., and Corpus, J. R., Int. J. Hydrogen Energy, 5, 383-399, 1980. With permission; (b) distribution, from Hammond, A. L., Metz, W. D., and Maugh II, T. H., Energy and the Future, American Association for the Advancement of Science, Washington, DC, 1973, 120. With permission of author.

(a)

(b)


330 Chapter 8

Another potential use of hydrogen comes from active H2-O2 fuel cell technology being developed for use in advanced stationary power and vehicle power applications. Fuel cell stationary power plant applications can incorporate H2 generating components, such as steam reforming utilizing natural gas, to supply hydrogen. Fuel cell in vehicle applications, much like the hydrogen-fueled engines, need compact H2 storage either as a cryogenic liquid, in anhydrides like iron titanium, or in hydrogen-containing fuel-reforming compounds like methanol.

Hydrogen has been a part of the aerospace energy inventory and successfully employed as a rocket fuel. In addition, hydrogen in liquid form appears to be a leading fuel contender for future commercial aviation applications, a field in which weight is a critical factor. In summary, hydrogen was seen in the recent past as not being a major fuel option, but it will begin to play a role in the coming decades.

Some of the more prominent negative aspects of a hydrogen fuel technology are economic, including the costs of production, transportation, storage, safety, and public acceptance. The fateful accident at Lakehurst, New Jersey, in 1937, when the hydrogen-filled German zeppelin Hindenburg caught fire and burned, has created public rejection of hydrogen, termed the Hindenberg syndrome. Many now believe, however, that the explosion and accident were associated with diesel fuel and not hydrogen. In fact, when a hydrogen leak occurs, it tends to escape rapidly, to rise vertically into the atmosphere and, if it catches fire, to provide little or no radiative heating because of the absence of carbon.

Fuel requirements in the new century will not be met by utilizing any one resource such as petroleum, coal, synfuels, or hydrogen. In fact, future energy needs will be based on a mix of all the fuels discussed in the last three chapters. The applied combustion engineer will, therefore, require a broad overview of fuel science in order to understand and to utilize most effectively the appropriate fuel option in each specific heat/power application.

8.7 GASEOUS FUEL BURNERS

Gaseous fuels do not require the charge preparation that liquid fuels do since they already exist naturally in a reactive state. The primary function of a gas burner is therefore to introduce a fuel-air mixture to the reaction zone at a proper AF ratio in order to sustain proper combustion. Essential components of a gas burner consist of a section for delivering reactants, a nozzle, and a flame holder. Gas burners operate as either low or high pressure configurations.

Natural gas systems that are used in domestic applications, such as cooking and heating, generally are low pressure units with many utilizing processes based on the classic Bunsen burner shown in Figure 8.9.

Suction induced by a jet of fuel gas delivered to base of burner draws primary air through a variable area.

Primary fuel-air mixture travels up the burner tube at an adequate velocity to prevent the flame from stroking back down the tube.

Fuel-air mixture burns with secondary air at the top of the burner in a diffusion flame.


Gaseous Fuels 331

Secondary air supply is provided by entrainment at outer envelope of flame at the top of the burner.

If primary air is delivered at a velocity much greater than maximum mixture flame speed the flame can be blown off and the burner extinguished.

Natural gas burners often use multi-jet arrangement, such as a ring configuration, to discharge fuel gas vertically into the required combustion space, such as near the floor level of a hot water heater or a furnace. Fuel-air ignition and combustion occur above the gas burner orifice.

Gaseous fuels due in part to their thermochemical properties and clean burning nature have replaced and/or supplemented many solid and liquid hydrocarbon fuels in heating and/or stationary power applications. Note that gaseous fuel preparation and burner components will be simpler than comparable systems used with solid and liquid fuels described in Chapters 6 and 7. In certain instances particular facilities are operated using dual-fuel burners, i.e., burners that can utilize either gas fuels, liquid fuels, or both types of fuels concurrently. This particular class of burners is found in use, for example, on waste incinerators where low energy liquid wastes that are difficult to thermally destroy are burned together with natural gas or oil.

Figure 8.9 Elements of a Bunsen burner.

gas

variable area

Bunsen burner

outer core

premixed primary fuel-air mixture

induced primary air

inner core


332 Chapter 8

Current industrial gas burners are classified in a variety of ways including according to the manner in which the fuel and air are combined. Fully premixed gas burners completely combine both fuel and oxidant (i.e., air or oxygen) prior to reaching the combustion zone. Partially premixed gas burners combine both fuel and oxidant as a flammable fuel-rich reactive mixture prior to the combustion zone. Secondary air is then introduced around the flame holder. Partially premixed burners have flame lengths, temperatures, and heat flux distributions that fall between the fully premixed and diffusion flames. In a diffusion-mixed burner both fuel and oxidant travel separately through the burner and exit unmixed prior to diffusion mixing in the combustion zone (recall a candle, the classic example of a diffusion flame). Nozzle mix gas burners also provide for both fuel and oxidant to travel separately through the burner prior to exiting unmixed into the combustion zone and mix rapidly or slowly allowing for a wide variation in flame shapes and swirl. Staged gas burners inject a portion of the fuel and/or air into the flame zone downstream of the principal flame using air staged burners or fuel staged burners. Staging is usually done to produce a longer flame with lower peak temperature and hence lower NOx with a more uniform heat flux distribution than non-staged flames.

Low temperature combustion of fully premixed gaseous fuel-air mixtures within certain porous materials, such as ceramic filaments and special metal alloy screens, has led to the development of the surface combustion burner. These solids, acting as flame holders and heat sinks, allow energy to be transferred by the combustion process to an application through heat transfer from the surface of the material. Surface combustion burners have the added benefit of being able to be contoured to match the heat transfer profile of an application.

Bluff body, swirl, and combinations are utilized predominantly as stabilizing mechanisms for gas burners. Air-swirl (strong rotary motion) provides greater stability to low energy content gaseous fuels because of their low flame speeds. Likewise air-swirl shortens the flame of high energy value fuel thereby providing greater control.

PROBLEMS

8.1 A homogeneous gaseous mixture of iso-octane and air has a specific gas constant of 51.255 ft lbf/lbm R. For the mixture, find (a) the % theoretical air; (b) the STP mixture density, kg/m3; (c) the equivalence ratio; and (d) the reaction mass FA ratio, lbm fuel/lbm air.

8.2 A homogeneous mixture of methane and air at STP has a specific heat ratio of 1.35. For this mixture, find (a) the molar constant pressure specific heat, kJ/kgmoleK; (b) the reactant mole fractions, %; (c) the mixture density, kg/m3; and (d) the mixture specific gravity.

8.3 A natural gas supply is composed of 20% CH4, 40% C2H6, and 40% C3H8, where all percentages are by volume. The Orsat analysis of dry combustion products yields 10.6% CO2, 3.0% O2, and 1.0% CO. Determine (a) the gravimetric fuel analysis, %; (b) the required theoretical AF ratio, kg air/kg fuel; (c) the reaction excess air, %; and (d) the mass of dry exhaust gases to mass of fuel fired, kg gas/kg fuel.


Gaseous Fuels 333

8.4 The limits of inflammability of ethane, C2H6, based on % volume of fuel vapor in reactive mixture are as follows:

Lower limit 3.22% Stoichiometric 5.64% Upper limit 12.45% Determine the AF corresponding to these three limits of inflammability, kg air/kg

fuel. 8.5 The volumetric analysis of a natural gas supply is 22.6% C2H6 and 77.4% CH4.

Find (a) the mass stoichiometric FA ratio, lbm fuel/lbm air; (b) the mass of CO, and H2O formed per mass of fuel, lbm gas/lbm fuel; (e) the gravimetric percentages of C and H2 in the fuel, %; (d) the dew point temperature for ideal stoichiometric combustion, F; and (e) the specific gravity of the dry exhaust gases for this natural gas.

8.6 A gaseous fuel having a volumetric analysis of 65% CH4, 25% C2H6, 5% CO, and 5% N2 is burned with 30% excess air. Find (a) the ideal mass of air supplied per unit mass of fuel, kg air/kg fuel; (b) the volumetric flow rate of STP air to that of gaseous fuel at STP conditions; (c) the reaction equivalence ratio; and (d) the moles of CO2 produced per mole of fuel.

8.7 A natural gas supply is to be augmented using a mixture of methane and propane. The supplier indicates that the specific gravity of the gas at STP conditions is 1.0. For this fuel, determine (a) the mole fractions of methane and propane, %; (b) the fuel density at STP, kg/m3; (c) the fuel higher heating value at STP, kJ/kg; and (d) the ratio of the answer to part (c) to the higher heating value of methane.

8.8 Propane, an LPG fuel resource, is supplied to a constant-pressure atmospheric burner at 77F. For a combustion efficiency of 87%, calculate (a) the ideal burner exhaust gas temperature, F; (b) the excess air, %; (c) the dry exhaust gas mole fractions, %; and (d) the dew point stack temperature, F.

8.9 A synthetic natural gas, or SNG, is to be generated using methane and propane. The lower heating value of the fuel at STP has a value of 37.25 MJ/m3. Calculate (a) the mixture molar density, kg mole/m3; (b) the fuel component mole fractions, %; (c) the fuel density at STP, kg/m3; and (d) the specific gravity of the fuel.

8.10 Gas burners can be fired with different gaseous fuels yet produce an equivalent performance as long as the gases have equal Wobble numbers. Consider a gaseous fuel mixture of 85% methane15% butane at STP, by volume. For stoichiometric combustion, find (a) the molar FA ratio, m3 fuel/m3 air; (b) the fuel specific gravity; (e) the fuel density, kg/m3; (d) the fuel HHV, MJ/m3; and (e) the fuel Wobble number, MJ/m3.

8.11 A cigarette lighter uses butane combustion in 200% theoretical air. Both fuel and air are at 25C, and the complete combustion products are at 127C. The gas-phase combustion occurs at 101 kPa. Determine (a) the molar AF, kgmole air/kgmole fuel; (b) the equivalence ratio; (c) the reactant mass fractions, %; (d) the dew point temperature, C; and (e) the heat released during combustion, kJ/kg fuel for the butane combustion.


334 Chapter 8

8.12 A flow calorimeter is used to measure the higher heating value of a natural gas. The gas is delivered to the calorimeter at 14.7 psi and 77F. The water supplied to the calorimeter has a mass flow rate of 1.3 lbm/min, with a corresponding temperature rise of 8.3F. The volume flow rate of the gas, measured using a wet test meter, is 0.01 ft3/min. Find (a) the heat absorbed by the water jacket, Btu/min; and (b) the higher heating value of the fuel, Btu/ft3.

8.13 A gaseous fuel has a specific gravity of 2.066 and a higher heating value at STP of 49,535 kJ/kg. Find: (a) the molecular weight of the fuel, kg/kgmole; (b) the density of the fuel, kg/m3; and (c) the higher heating value of the fuel, kJ/m3.

8.14 A gas furnace burns 2.5 ft3/hr of a gaseous fuel in 25% excess air. The fuel volumetric analysis yields 90% CH4, 7% C2H6, and 3% C3H8. Both fuel and air enter the atmospheric burner at 77F, while flue gases exit at a temperature of 1,880F. Assuming ideal combustion, calculate (a) the dry flue gas analysis, %; (b) the product volumetric flow rate, ft3/hr; (c) heat release, Btu/hr; and (d) the furnace efficiency, %.

8.15 A portable furnace burns a propane-air mixture having a 0.8 equivalence ratio. The fuel-air supply to the burner is at 25C and 101 kPa, with the gases leaving the stack at 127C. Assuming ideal complete combustion, find (a) the ideal flue gas molecular weight, kg/kgmole; (b) the exhaust dew point temperature, C; (c) the mass of CO2 produced per mass of fuel supplied, kg gas/kg fuel; and (d) the furnace efficiency, %.

8.16 Methane and air are supplied to a constant-pressure burner at 108 kPa and 25C. The dry products of combustion mole fractions are 6.95% CO2, 3.02% O2, and 90.00% N2. The dew point temperature of the products is 100C. Determine (a) the molar AF ratio, kgmole air/kgmole fuel; (b) the exhaust gas molecular weight, kg/kgmole; (c) the combustion heat transfer if the exhaust gases are at 100C; and (d) the combustion efficiency, %.

8.17 A fuel gas mixture is supplied to a furnace at 15 psia and 77F. The mixture, burned in 15% excess air, consists of the following constituents by volume:

CH4 60% C2H6 30% CO 10%

If air is supplied at 14.7 psia and 80F calculate: (a) the ft3 air/ft3 fuel; and (b) the fan power required when burning fuel at a rate of 100,000 ft3/hr, hp.

8.18 Acetylene is burned using a constant-pressure water-cooled burner. Fuel is supplied at 200 kPa and 15C, while air supply enters the burner at 200 kPa and 20C. The products leave the unit at 150C. Water supplied at a flow rate of 0.25 kg/sec enters the jacket at 20C and leaves at 120C. Calculate (a) the heat transfer rate to cooling water, W; (b) the total mass flow rate of fuel and air, kg/see; (c) the volumetric flow rate of dry exhaust gases, m3/sec; and (d) the rate of condensation of water in the exhaust, kg/sec.

8.19 A hot water heater receives feed water at 60F and produces hot water at 120F. The gas-fired unit produces 30-gal water/hr and burns methane at STP reactant conditions. The burner design requires 130% theoretical air combustion. Calculate (a) the required heat transfer rate to the water, Btu/hr; (b) the gas flow rate, ft3/min; (c) the dew point temperature, F; and (d) the boiler efficiency, %.


Gaseous Fuels 335

8.20 Methane is burned initially at 1 atm and 25C in 20% excess air. The adiabatic flame temperature for the constant-pressure combustion process is 2500K. For complete combustion, calculate (a) the ideal reaction equivalence ratio; (b) the frozen product mole fractions, %; and (c) the air preheat temperature needed to produce these results, K.

8.21 A furnace designed to burn coal gas in 60% excess air is to be converted to a biomass methane gas. Design requirements are to provide the same energy transfer, using the same volumetric supply rate of air. Fuel and air are supplied at STP. Composition of the two gaseous fuels are:

Coal gas Biogas

30.0% CH4 90.0% CH4 3.6% C2H4 2.0% CO2 8.0% CO 8.0% N2

52.0% H2 0.4% O2 2.0% CO2 4.0% N2

For these conditions, determine (a) the maximum energy release rate for 100 m3/sec of air, kW; (b) the excess air requirements for the converted burner, %; (c) the ratio of volumetric fuel flow rates; and (d) the Wobble number for the two fuels, mJ/m3.

8.22 A mixture of 1 part by volume of ethylene to 50 parts by volume of air is ignited in a closed rigid vessel. The initial pressure and temperature of the charge mixture is 10 atm and 300K. Calculate (a) the mixture equivalence ratio; (b) the maximum adiabatic temperature, K; and (c) the maximum adiabatic pressure, atm.

8.23 A carbureted water gas has the following composition:

16.0% C2H4 32.3% H2 2.9% CO2 19.9% CH4 26.1% CO 2.8% N2

Flue gas analysis of the combustion process yields:

11.83% CO2 4.53% O2 83.24% N2 0.4% CO For combustion at STP, compute (a) the volumetric flow rate of air to the volumetric flow rate of fuel, ft3 air/ft3 fuel; (b) the volumetric flow rate of flue gases at 620F to flow rate of fuel, ft3 gas/ft3 fuel; (c) the equivalence ratio for the reaction; and (d) the ideal combustion efficiency for the reaction with the stack gases at 620F.

8.24 Methane and air at an equivalence ratio of 0.9 are supplied to a boiler at STP. Compute the following under the assumption of complete combustion: (a) dew point temperature for the reaction, F; (b) heat release per mole of fuel assuming Tprod = 720R; and (c) boiler efficiency for part (b), %.


336 Chapter 8

8.25 A hot water heater receives feed water at 60F and produces hot water at 120F. The gas-fired unit burns 0.73 lbm/hr of methane, CH4, and produces 30 gal/hr of hot water. If the heater is supplied with fuel and air at STP, calculate (a) the required heat transfer to the water, Btu/hr; (b) the boiler efficiency, %; (c) the gas consumption, ft3/min; (d) the ideal dry flue gas analysis for 130% theoretical air combustion; and (e) the product dew point temperature, F.

8.26 The preliminary design for a low-pollution steam power plant is required to satisfy the following design specifications: 1 106-kW net power plant output; 40% steam cycle thermal efficiency; CH4 fuel source; 15% excess air for combustion; 1 atm and 25C burner air supply; 1 atm and 227C flue gas conditions. For complete ideal combustion, determine (a) the ideal Orsat analysis, %; (b) the dew point temperature, C; (c) the fuel mass flow rate for a stack temperature that is 10C greater than the dew point temperature, kg fuel/hr; and (d) the combustion efficiency, %.

8.27 The following dry product analysis is for methane and air constant pressure combustion at Tprod = 1,200K:

O2 4.6% N2 85.46% CO 1.14% CO2 8.33% H2 0.47% Using these data determine the following: (a) percent theoretical air for the

reaction, %; (b) AF ratio, kg air/kg fuel; (c) dew point temperature, C; and (d) heat released by the reaction 1Q2 , kJ/m3 CH4.

8.28 Catalytic methanization of synthesis gas is necessary to produce an SNG of approximately 9098% methane and occurs via the reaction

CO + 3H2 CH4 + H2O

For the SNG methanization process with a H2/CO molar feed ratio of 3 to 1, at a pressure and temperature of 1 atm and 1,000K, obtain: (a) the equilibrium constant, KP, for the methanization reaction in terms of the definition and the constituents; (b) the equilibrium constant, KP, for the methanization reaction in terms of JANAF data for the constituents for the reaction; and (c) the equilibrium composition mole fractions for mixture at a pressure and temperature of 1 atm and 1,000K.


Table of ContentsChapter 8: Gaseous Fuels8.1 INTRODUCTION8.2 GASEOUS FUEL PROPERTIES8.3 NATURAL GAS8.4 COAL-DERIVED GASEOUS FUELS8.5 BIOMASS AND SYNTHETIC NATURAL GAS8.6 HYDROGEN8.7 GASEOUS FUEL BURNERSPROBLEMSAppendixesBibliography

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Gaseous Fuels

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